It is well known in the art that severe dynamic conditions are sometimes encountered during drilling. Commonly encountered dynamic conditions include, for example, axial vibration, lateral shock and vibration, torsional vibration, stick/slip, and whirl. Bit bounce includes axial vibration of the drill string, sometimes resulting in temporary lift off of the drill bit from the formation (“bouncing” of the drill bit off the bottom of the borehole). Axial vibrations (e.g., bit bounce) is known to reduce the rate of penetration (ROP) during drilling, may cause excessive fatigue damage to BHA components, and may even damage the well in extreme conditions.
Lateral vibrations are those which are transverse to the axis of the drill string (cross-axial). Such lateral vibrations are commonly recognized as a leading cause of drill string, drill string connection, and BHA failures and may be caused, for example, by bit whirl and/or the use of unbalanced drill string components.
Stick/slip refers to a torsional vibration induced by friction between drill string components and the borehole wall. Stick/slip is known to produce instantaneous drill string rotation speeds many times that of the nominal rotation speed of the table. In stick/slip conditions a portion of the drill string or bit sticks to the borehole wall due to frictional forces often causing the drill string to temporarily stop rotating. Meanwhile, the rotary table continues to turn resulting in an accumulation of torsional energy in the drill string. When the torsional energy exceeds the static friction between the drill string and the borehole, the energy is released suddenly in a rapid burst of drill string rotation. Instantaneous downhole rotation rotates have been reported to exceed four to ten times that of the rotary table. Stick/slip is known to cause severe damage to downhole tools, as well as connection fatigue, and excess wear to the drill bit and near-bit stabilizer blades. Such wear commonly results in reduced ROP and loss of steerability in deviated boreholes.
Bit or stabilizer whirl may be caused by the instantaneous center of rotation moving around the face of the bit (or about the axis of the string). The movement (rotation of the whirl) is generally in the opposite direction of the rotation of the drill string (counterclockwise vs. clockwise). Cutting elements on a whirling bit have been documented to move sideways, backwards, and at much higher velocities than those on a non-whirling bit. The associated impact loads are known to cause chipping and accelerated wear of the bit components. For example, severe bit damage has been observed even after very short duration drilling operations for polycrystalline diamond compact (PDC) bits.
These harmful dynamic conditions not only cause premature failure and excessive wear of the drilling components, but also can result in costly trips (tripping-in and tripping-out of the borehole) due to unexpected tool failures and wear. Furthermore, there is a trend in the industry towards drilling deeper, smaller diameter wells where damaging dynamic conditions can become increasingly problematic. Problems associated with premature tool failure and wear are exacerbated (and more expensive) in such wells.
The above-described downhole dynamic conditions are known to be influenced by drilling parameters. By controlling such drilling parameters an operator can sometimes mitigate against damaging dynamic conditions. For example, bit bounce and lateral vibration conditions can sometimes be overcome by reducing both the weight on bit and the drill string rotation rate. Stick/slip conditions can often be overcome via increasing the drill string rotation rate and reducing weight on bit. The use of less aggressive drill bits also tends to reduce bit bounce, lateral vibrations, and stick/slip in many types of formations. The use of stiffer drill string components is further known to sometimes reduce stick/slip. While the damaging dynamic conditions may often be mitigated as described above, reliable measurement and identification of such dynamic conditions can be problematic. For example, lateral vibration and stick/slip conditions are not easily quantified by surface measurements. In fact, such dynamic conditions are sometimes not even detectable at the surface, especially at vibration frequencies above about 5 hertz.
Downhole dynamics measurement systems have been known in the art for at least 15 years. While these, and other known systems and methods, may be serviceable in certain applications, there is yet need for further improvement. For example, known systems typically make use of dedicated sensors which tends to increase costs and expend valuable BHA real estate (e.g., via the introduction of a dedicated dynamics measurement sub). Also, such dedicated sensors tend to increase power consumption and component counts and, therefore, the complexity of MWD, LWD, and directional drilling tools, and thus tend to reduce reliability of the system. Moreover, dedicated sensors must typically be deployed a significant distance above the drill bit.
Therefore there exists a need for an improved method for making downhole dynamics measurements and particularly for making such measurements as close to the drill bit as possible.